Method for zonal extensional production of hydrocarbons

ABSTRACT

A method for producing hydrocarbons from a subsurface reservoir involves identifying hydraulically isolated target and trigger reservoirs. A fluid is produced from the trigger reservoir to create an extension zone in the target reservoir. A portion of the extension zone is subjected to an action such as zonal dilation, zonal extension, extensional mechanical fracturing, opening of natural fractures, pore volume expansion, and/or microfracturing of mineral grains and grain cements. Production of the trigger reservoir fluid is ceased and then a hydrocarbon is produced from the target reservoir.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority benefit of U.S. Provisional Application No. 62/934,649 filed Nov. 13, 2019, which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The present invention relates to a method for enhancing hydrocarbon production from a subsurface rock formation, and in particular to zonal extensional production of hydrocarbons.

BACKGROUND OF THE INVENTION

It has been found that as a producing oil and gas reservoir contracts and compacts from the extraction of oil and gas from within the rock formation there is an accompanying geomechanical response involving vertical stretching of the overlying rock strata. This vertical stretching is known as the process of ‘overburden extension’.

Hatchell and Bourne (“Measuring reservoir compaction using time-lapse timeshifts” 2005-75^(th) Ann. Internat. Mtg., Soc. Expl. Geophys., 2500-2503) conducted 4D time lapse seismic images of subsurface rock formations during the production of an oil and gas reservoir. They noted that, during the production of hydrocarbons from a reservoir, the rock formation will internally compact and shrink due to the extraction of the oil and gas. They noted a very different response in the overlying rocks (e.g. the overburden) where these rock formations actually stretched and expanded. The expanding overburden (and its increase in layer thickness) were evidenced by slower seismic velocities that increase seismic travel times on the 4D time lapse seismic images. The expansion in the overburden was observed to occur field-wide.

Scott (“The effects of stress paths on acoustic velocities and 4D seismic imaging” The Leading Edge pp. 602-608; May 2007) noted that the pattern of wellbore failures observed in producing oil and gas fields reflected the same rock deformational patterns observed in Hatchell and Bourne's (2005) 4D seismic images (e.g. compaction in the reservoir vs extension in the overburden). Scott (2007) noted that, inside the reservoir wellbore, casings will internally buckle from compaction of the rocks. In the overburden rock overlying the producing reservoir wellbore casings traditionally show patterns of tensional parting from expansion and stretching of rock column overlying the reservoir. Scott (2007) additionally suggested that laboratory derived experimental results (from stress-path triaxial tests) indicate that the overburden rocks will undergo dilational microcracking (e.g. fracturing) during the extensional deformational process—an observation which would reinforce the pattern of decreases in acoustic velocities in the overburden previously noted by Hatchell and Bourne (2005).

The impact of compaction and subsidence was also studied by Doornhof et al. (“Compaction and subsidence” Oilfield Review pp. 50-68; 2006). In addition to the potential adverse effects on casings highlighted by Scott, Doornhof et al. further discusses the problem of flow of weakened material into a wellbore, such as in the North Sea, where weakened chalk flowed like toothpaste into the wellbore. Doornhof et al. illustrate the effect of the formation of a ‘stress arch’ over the Valhall field showing its relationship to the developing zone of extension above the compacting reservoir. Doornhof et al. describe the process as follows. As an oil and gas reservoir compacts, the overburden column of rock will stretch (e.g. extension). As a result of this stretching, the elastic stresses in the overburden will form a ‘stress-arch’ which redistributes stresses to the lateral margins of the rock formation. Doornhof et al. also noted two interesting features about this overburden extension. The first is that the overburden extension process can occur surprising quickly—on the scale of months, instead of the years or decades of production. This is was evidenced by the re-logging of sidetracked wells in Vahall Field in the North Sea that showed that overburden extension occurred after only a five month time interval. The second surprising aspect of overburden extension noted by Doornhof et al. is that it can occur locally—right around a single producing wellbore (instead of the field wide overburden extensional deformational behavior previously observed on 4D time lapse seismic imaging in Hatchell and Bourne 2005.

The negative impacts of the formation of the ‘stress-arch’ and ‘overburden extension process on the drilling of wellbores were discussed by van Bergen et al. (SPE 166574 “Shearwater—securing the chalk—Effects of Depletion of a HPHT Reservoir on Chalk Overburden” 2013) and in a follow-on paper by Jones et al. (“The Shearwater Field—Understanding the Overburden Above a Geologically Complex and Pressure-depleted High-pressure and High-temperature Field” Petroleum Geology Conference series 8:429-443; 3 Jul. 2017). In both publications, the authors explain that the initial series of wells drilled in the Shearwater Field encountered little or no drilling problems. However, later infill wells encountered severe problems while drilling through the overburden rock layers overlying the producing reservoir. The problems included wellbore failures (in the form of linear deformation), increases in annular pressure, and a surprising influx of mobilized gas (which was not observed in initial wells drilled in the field). van Bergen et al. determined that the problems encountered during drilling were the direct result of the ‘stress-arching’ and ‘overburden extension’ process above the Shearwater reservoir. They noted that the overburden extension process actually created new fractures throughout the overlying rock formations (as seen on imaging logs) and that these newly developed fractures increased the permeability of those rocks and mobilized previously immobile hydrocarbons within those rocks. In addition, they documented that these fractures were created throughout a large lithologic section (e.g. zone) in the overburden rock formations beneath the stress arch.

Jones et al. and van Bergen et al. provided their findings in an effort to assist others in the design and safe delivery of infill wells for overcoming the subsurface challenges associated with drilling in a depleted HPHT setting.

Many in the oil and gas industry have studied the effects on modifying permeability for improving the production of hydrocarbons from reservoirs. Two general classes of methods have traditionally been used for increasing formation permeability via fracturing of the formation during the oil and gas production operations. The first involves fluid extraction techniques (like solution mining) as the primary recovery mechanism and the second involves processes such as fluid injection (like hydraulic fracturing).

For example, Hawthorn et al. (US20160251947A1, 1 Sep. 2016) relates to a method for modifying formation properties by drilling a wellbore into a first geologic layer in proximity to a second geologic layer and removing material (e.g. extraction) from the first geologic layer to modify the properties of the first and second geologic layers. Material removal processes include solution mining of a salt formation and acidizing carbonates. According to Hawthorn et al., solution mining to dissolve salts or acidizing to dissolve carbonates may change the stress regime, weaken a mineral layer or reduce the support the mineral layer provides to the rest of the formation. Hawthorn et al. contemplate that material removal may cause cracks in the surrounding rocks. Other solution mining processes involve the creation of cavities or caverns in U.S. Pat. No. 3,759,574 (Beard) and U.S. Pat. No. 4,398,769 (Jacoby).

Dale et al. (US20130199781A1) relates to fracturing by applying stress in a zone (e.g. injection fluid pressure) proximate to a subterranean formation to indirectly translate a mechanical stress to the formation. Similarly, Dale et al. (US20130206412A1) describes fracturing by reducing geomechanical stress to the proximate zone to translate a geomechanical stress change causing a mechanical dislocation, which create fractures in a formation. The methods described by Dale et al. rely on delamination fracturing stimulation. A well is drilled through a hydrocarbon-bearing formation into a treatment zone. Fluids and/or particulate solids are injected into the treatment zone to dilate, uplift, “arch,” and shear fracture the hydrocarbon-bearing formation. As illustrated, for example, in FIG. 6 of both Dale et al. references, this ‘arch’ is, in effect, a physical arching of the rock layers—not an ‘arching of stresses’ as described in Doornhof et al. As shown more clearly in the drawings, Dale et al.'s processes lift the formation layers (each maintained at substantially the same thickness) leading to sliding or breaking of the hydrocarbon-bearing formation along layers and fracture planes, also referred to as bedding plane shear. Finally, in US20130199787A1, Dale et al. create a notch in a formation, cause a volumetric change in a treatment interval to apply a mechanical stress on a production interval (e.g. an injection pressure), and creating a horizontal fracture in the formation originating from the notch.

U.S. Pat. No. 8,408,313B2 (Yale et al.) describes recovering heavy oil from a formation having an overburden stress thereon. The formation is conditioned by increasing fluid pressure throughout with an injection fluid, thereby relieving overburden stress to allow uncemented sands in the formation to become mobile.

Other methods for hydraulic fracturing have been long used in the industry (see, for example, Farris (U.S. Pat. No. 2,596,843, U.S. Pat. No. RE23,733), Clark (U.S. Pat. No. 2,596,844), Brandon (U.S. Pat. No. 3,220,475)). These methods create discrete single fracture (or at best a few fractures) in the rocks and which have only a limited distributed within a given volume of rock. These methods, as do the Dale et al. citations involve fluid (e.g. hydraulic) injection to treat the primary targeted reservoir.

There is a need for a method for enhancing the production of hydrocarbons from a subsurface rock formation whereby a ‘zone’ of fracturing is created within the targeted hydrocarbon reservoir.

SUMMARY OF THE INVENTION

According to one aspect of the present invention, there is provided a method for production of a hydrocarbon from a subsurface reservoir, comprising the steps of: (a) identifying a target reservoir, the target reservoir bearing hydrocarbons; (b) locating a trigger reservoir proximate the target reservoir, the trigger reservoir being hydraulically isolated from the target reservoir; (c) producing a fluid from the trigger reservoir, thereby creating an extension zone in the target reservoir, wherein a portion of the target reservoir having the extension zone is subjected to an action selected from the group consisting of zonal dilation, zonal extension, extensional mechanical fracturing, opening of natural fractures, pore volume expansion, microfracturing of mineral grains and grain cements, and combinations thereof; (d) ceasing production of the fluid from the trigger reservoir; and (e) producing a hydrocarbon selected from oil, gas and combinations thereof from the target reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention will be better understood by referring to the following detailed description of preferred embodiments and the drawings referenced therein, in which:

FIG. 1 is arecreation of FIG. 7 of van Bergen et al. (SPE166574; 2013);

FIGS. 2A-2C illustrate cross-sectional views of a subsurface subjected to one embodiment of the method of the present invention;

FIG. 3 illustrates effects, in a cross-sectional view, of another embodiment of the method of the present invention, where a trigger reservoir is located below a target reservoir;

FIG. 4 illustrates effects, in a cross-sectional view, of a further embodiment of the method of the present invention, where a trigger reservoir is located above a target reservoir;

FIGS. 5A and 5B graphically compare the effect of drawdown pressure on reservoir pore fluid pressure; and

FIG. 6 illustrates a cross-sectional view of a subsurface subjected to another embodiment of the method of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a method for producing hydrocarbons from a subsurface reservoir. To better understand the surprising discovery made by the present inventor for enhancing hydrocarbon production, it is useful to illustrate the adverse effect of stress arching generally understood by those skilled in the art.

FIG. 1 is a recreation of FIG. 7 in van Bergen et al. discussed above. As explained in van Bergen et al. and Jones et al., production of hydrocarbons from the Fulmar reservoir interval 1 resulted in weakening of the Hod chalk overburden formation 3, above caprock 2, and the Tor chalk formation 4 due to stress arching. In initial field testing results, the Hod chalk overburden formation 3 was found initially to be a tight impermeable formation. However, after some depletion of hydrocarbons in the Fulmar reservoir interval 1, fractures were produced in both the Hod chalk overburden formation 3 and the Tor chalk formation 4. As a result of production in the Fulmar reservoir interval 1, well failure was found to be attributed to (1) expansion (extension) in the Hod chalk overburden formation 3 and (2) compression in the Tor chalk formation 4. van Bergen et al. determined that expansion, depicted by arrows 5, in the Hod chalk formation 3 opened horizontal fractures 6 and vertical fractures 7. With respect to the Tor chalk formation 4, van Bergen et al. determined that compression, depicted by arrows 8, resulted in opening horizontal fractures 6 and closing vertical fractures 7. In addition, testing indicated that the original immobile gaseous hydrocarbons present in the Hod chalk formation 3 had adversely become mobile due to the increased permeability created by the development of these same horizontal fractures 6 and vertical fractures 7. van Bergen et al. state that the expansion and the opening of fractures in the Hod chalk overburden 3 and the Tor chalk overburden 4 formations was a direct result of depletion from the Fulmar reservoir interval 1 and was a direct consequence of the so-called ‘stress arching’ effect, depicted in FIG. 1 by stress arch 9.

As discussed above, Jones et al., van Bergen et al. and others provided their findings in an effort to assist others in the design and safe delivery of infill wells for overcoming the subsurface challenges associated with drilling in a depleted HPHT setting. Their findings also attempted to explain the unexpected influx of hydrocarbons into well bores during the drilling of infill wells by what were originally thought were immobile in situ hydrocarbons in tight impermeable formations in a lithologic section significantly above the actually targeted producing Fulmar reservoir 1.

The present inventor surprisingly discovered that it is possible to convert the adverse effect of a stress arch/extensional zone effect observed by van Bergen et al. into a new method for enhancing the production of hydrocarbons from a subsurface reservoir. Although the method of the present invention is widely applicable to a variety of subsurface formations, it is particularly advantageous for the production of hydrocarbons from deepwater wells where high pressures and stresses are present. The method of the present invention creates zones of enhanced permeability and/or fluid mobility in targeted sections of the rock column allowing previously immobile hydrocarbons to become mobile and productive.

An embodiment of the method of the present invention 10 is illustrated in FIGS. 2A-2C. In FIG. 2A, a target reservoir 12 bearing hydrocarbons is identified. A trigger reservoir 14 is located proximate the target reservoir 12. At the outset, the trigger reservoir 14 is hydraulically isolated from the target reservoir 12. By “hydraulically isolated,” we mean that there is substantially no naturally occurring fluid communication between the target reservoir 12 and the trigger reservoir 14. For example, without limitation, the target reservoir 12 and the trigger reservoir 14 may be hydraulically isolated by a sealing caprock 19 or other layer of relatively impervious rock, such as shale. The method of the present invention is particularly suited to target reservoirs that have relatively low permeability and/or relatively immobile hydrocarbons.

This hydraulic isolation is preferably maintained during production from the trigger reservoir 14 for optimal effect. It will be understood that the caprock 19 may be also be fractured in the extension zone 22 during production of the trigger reservoir 14. Preferably, the caprock 19 comprises shale. Shale is relatively impervious and, due to the fissile nature of shale, fractures in the caprock 19 will typically be oriented horizontally and open vertically. For example, van Bergen et al. and Jones et al. show that the majority of these fractures created in the caprock 19 will be horizontally oriented. This observation means that vertical hydraulic isolation will be maintained between the trigger reservoir 14 and the target reservoir 12 even though the sealing caprocks 19 are also undergoing fracturing in the zone of extension.

As depicted in the drawings, caprock 19 extends between the target reservoir 12 and the trigger reservoir 14. However, there may be one or more other layers between the target reservoir 12 and the trigger reservoir 14. FIGS. 2A-2C also show caprock 19 above the target reservoir 12 and below the trigger reservoir 14. These caprock 19 layers may or may not be contiguous to the respective target reservoir 12 and the trigger reservoir 14.

Returning to the discussion of FIG. 2A, fluid in the trigger reservoir 14 is produced, as depicted by the arrows 16, through well 18. Those skilled in the art will understand the procedures involved for establishing the well 18 and the steps, for example, perforating a reservoir, isolating the various reservoirs using isolation packers, for causing fluid to be produced.

Preferably, fluid is produced for a relatively short period of time, for example, in a range of 2 to 6 months. Preferably, fluid is produced from the trigger reservoir 14 at a hard drawdown rate. A ‘hard’ drawdown rate is a term of art understood by those skilled in the art as being a very fast fluid withdrawal and a rate that imposes a sharp near well-bore pressure gradient. The actual rates will be dependent on a variety of factors including, without limitation, fluid properties, rock properties, depth, and the like.

As shown in FIG. 2B, continued production of fluid from the trigger reservoir 14 creates an extension zone 22 in the target reservoir 12. As a result, a portion of the target reservoir 12 is subjected to an action including zonal dilation, zonal extension, extensional mechanical fracturing, opening of natural fractures, pore volume expansion and/or microfracturing of mineral grains and grain cements. Zonal dilation refers to a volumetric expansion of rock by opening horizontal and vertical fractures. Zonal extension refers to a directional expansion in a single azimuthal direction, for example only in a vertical direction, which would open only horizontal fractures.

Preferably, the production of fluid from the trigger reservoir 14 creates a region of compaction zone 28 in the trigger reservoir 14. As will be discussed in more detail with reference to FIGS. 3 and 4, without being bound by theory, the compaction zone 28 in the trigger reservoir 14 generates a concurrent extension zone 22 in the target reservoir 12 and this leads to the development of the ‘stress-arch’ 34.

As depicted in the embodiment shown in FIG. 2B, extension of the target reservoir 12 causes horizontal extensional mechanical microcracks and/or fractures 24 to open.

Turning now to FIG. 3, without being bound by theory, various effects of one embodiment of the method of the present invention 10 are illustrated for a target reservoir 12 located above a trigger reservoir 14. When fluid is produced from the trigger reservoir 14, a portion of the trigger reservoir 14 becomes compacted in a region around the well 18, as represented by compaction arrows 32. Compressive stresses generated by the compacting trigger reservoir 14 forms an overlying stress arch 34.

The stress arch shifts compressive stresses to lateral margins at the sides of the compacting trigger reservoir 14, forming a type of stress ‘compression pillar’ effect at the lateral edges of the compacting trigger reservoir 14.

Beneath the stress arch 34, a zone of vertical extension 22 is created in the overburden and underburden rock sections, above and below the compacted region of the trigger reservoir 14, respectively.

The effects are also illustrated in another embodiment of the method of the present invention 10, depicted in FIG. 4, where the target reservoir 12 is located below a trigger reservoir 14.

Returning now to FIG. 2C, production of fluid from the trigger reservoir 14 is stopped. Hydrocarbons are then produced, as depicted by arrows 26, from the target reservoir 12.

After producing hydrocarbons from the target reservoir 12 for some time, it may be desirable to further improve permeability and/or mobility by repeating the steps of producing fluid from the trigger reservoir 14, stopping production and producing hydrocarbons from the target reservoir 12.

The trigger reservoir 14 may be comprised of brine-saturated rock, or a reservoir having lower value hydrocarbons, such as hydrocarbons with a high water saturation, a mixed phase reservoir, or a previously produced reservoir. Preferably, the trigger reservoir 14 is, in itself, one that is uneconomically produced relative to the target reservoir 12. Accordingly, the fluid produced from the trigger reservoir 14 may include brine, hydrocarbons, water, and combinations thereof.

Preferably, fluid is produced from the trigger reservoir 14 to cause a localized controllable drawdown pore fluid pressure gradient, as compared with an objective to deplete the entire trigger reservoir 14. Causing a localized drawdown pressure gradient in the trigger reservoir 14 produces a more desirable localized stress-arch/extension phenomenon in the overlying/underlying rock units, as compared to a more distributed effect.

Preferably, fluid is produced from the trigger reservoir 14 in a manner so as to produce a hard drawdown. Typically, ‘hard’ drawdown rates involve decreasing pore fluid pressures to values that are 20% lower than the initial reservoir pore fluid pressure. ‘Soft’ drawdown rates typically used in reservoir production involve a reduction in pressures that are around 5% of the of the original pore fluid pressure in the reservoir.

Preferably, the trigger reservoir 14 and the target reservoir 12 are located in a geological basin where abnormally high pore fluid pressure are already present (examples of such basins are the North Sea or the U.S. Gulf of Mexico). As an example, normal pore fluid pressures could be around 8.6 ppg (for a brine) and, therefore, any pore fluid pressures above the normal pore fluid pressure would be considered ‘abnormal’. The presence of abnormal pore fluid pressures in the trigger reservoir 14 facilitates the ease and speed of fluid extraction from the trigger reservoir 14.

Preferably, the trigger reservoir 14 has a high porosity (e.g. allowing for an easier compaction of the trigger reservoir 14) and a high permeability (thereby making it easier to induce fluid extraction to trigger the compaction process in the trigger reservoir 14), is present in a high pressure environment (e.g. deepwater) and is present in an geological basin (e.g. the U.S. Gulf of Mexico or the North Sea) where abnormally high fluid pressures are present to create to driving force to produce the trigger reservoir 14.

The invention is particularly advantageous where the target reservoir 12 has a low initial permeability (e.g. a tight rock) or has heavy viscous hydrocarbons which are difficult to mobilize.

FIGS. 5A and 5B graphically compare the effect of a near wellbore soft drawdown pressure gradient to a hard drawdown pressure gradient on pore fluid pressure 51 as a function of distance from a well 18. FIG. 5A represents an initial stage pore fluid pressure gradient, while FIG. 5B illustrates a later stage pore fluid pressure gradient. A depletion pore fluid pressure change is shown by the double-headed arrow 62. An initial reservoir pore fluid pressure (P_(p)) is depicted at line 52. The initial near wellbore 54 pore fluid pressure gradients are shown in FIG. 5A, for a soft drawdown pressure 56 and a hard drawdown pressure 58. FIGS. 5A and 5B illustrate that the greater the pore pressure drawdown gradient near the wellbore, the greater the increase in the effective stress internally within the trigger reservoir 14 according to the equation:

σ_(veff)=σ_(v) −P _(p)

where σ_(veff) is the effective stress internally within the trigger reservoir 14 resulting from the rock column, σ_(v) is the stress internally within the trigger reservoir 14 resulting from the rock column and P_(p) is the pore fluid pressure. The increase in σ_(veff) created by the decrease in pore fluid pressure in the drawdown zone (number) results in localized compaction of the trigger reservoir 14 and this in turn causes extension in the target reservoir 12.

It will be understood by those skilled in the art that drawdown pore pressure fluid withdrawal rates from a reservoir are conventionally selected to balance two competing effects: (1) the extraction of the oil and gas as fast as possible; while (2) preserving the quality of the reservoir (e.g. not damaging or severely compacting it).

In accordance with the present invention, the motivation of drawdown during the production of the trigger reservoir 14 is very different. Specifically, preservation of the trigger reservoir 14 quality has no importance during its short production life (e.g. months). The fluid is extracted as fast as possible to cause permanent compaction of the trigger reservoir 14. With this understanding, the size, shape, and geometry of the extensional fracture zone in the target reservoir 12 is controllable in a manner known to those skilled in the art. For example, the rate of pore fluid production in the trigger reservoir 14 may be changed to alter the near wellbore pore fluid drawdown fluid pressure gradients 56, 58. In one embodiment, a slow ‘soft’ drawdown profile 56 will create a very large extensional zone, but this type of effect may create distributed low intensity fractures with a low impact on formation permeability. In another embodiment, a ‘hard’ drawdown profile 58 will create a very localized small zone, but this region will exhibit high intensity fracturing and have a larger effect on the target reservoir 12 permeability. To achieve this control, petroleum engineers skilled in the art, may use finite element mathematical models to compare and test various drawdown profiles allowing them to select the most optimum drawdown for creating an extensional fracture zone of a given size and shape within the target reservoir 12.

In another embodiment of the method of the present invention, the target reservoir 12 may be subjected to hydraulic fracture stimulation to further enhance permeability and/or connectivity of the mechanical fractures created while producing fluids from the trigger reservoir 14. The hydraulic fracture stimulation of the target reservoir 12 may be conducted after ceasing producing the fluid from the trigger reservoir 14 and/or after producing hydrocarbons from the target reservoir 12. In yet another embodiment, the method of the present invention may be applied to target reservoir 12 that has already been subjected to hydraulic fracturing. In still another embodiment, the method of the present invention may further comprise the step of first hydraulic fracturing the target reservoir 12 before producing fluid from the trigger reservoir 14. In each of these embodiments, the method of the present invention may also be alternated with hydraulic fracturing.

As illustrated in FIGS. 2A-2C through FIGS. 5A and 5B, the wells 18 are vertically disposed. FIG. 6 illustrates a further embodiment of the method of the present invention 10, wherein the wells 66, 68 are horizontally disposed in the target reservoir 12 and the trigger reservoir 14, respectively.

Fluid in the trigger reservoir 14 is produced, as depicted by the arrows 16, through well 68. Those skilled in the art will understand the procedures involved for establishing the well 68 and the steps, for example, perforating a reservoir and the setting of isolation packers, for causing fluid to be produced.

Preferably, fluid is produced for a relatively short period of time, for example, in a range of 2 to 6 months. Preferably, the fluid is produced from the trigger reservoir 14 at a hard drawdown rate.

Continued production of fluid from the trigger reservoir 14 creates an extension zone 22 in the target reservoir 12. As a result, a portion of the target reservoir 12 is subjected to an action including zonal dilation, zonal extension, extensional mechanical fracturing, opening of natural fractures, pore volume expansion and/or microfracturing of mineral grains and grain cements.

Compaction of the trigger reservoir 14 causes horizontal extensional mechanical microcracks and/or fractures 24 in the target reservoir 12. Production of fluid from the trigger reservoir 14 is then stopped to produce hydrocarbons, as depicted by arrows 26, from the target reservoir 12, through well 66.

In this embodiment, each localized compaction zone along the trigger well 68 is preferably successively produced to enhance the permeability along selected sections of the overlying target reservoir 12.

It will be understood by those skilled in the art that the relative sizes and extent of the zones depicted in the cross-sectional drawings herein are dependent on various factors included the types and thicknesses of layers of the subsurface formation, the length of production time, mobility of fluids in the trigger reservoir, degree of drawdown pressure, and the like. Also, it will be understood that the effects are illustrated in cross-section and that the effects will be three-dimensional, though in some cases the effects will not be identical throughout.

While preferred embodiments of the present invention have been described, it should be understood that various changes, adaptations and modifications can be made therein within the scope of the invention(s) as claimed below. 

What is claimed is:
 1. A method for production of a hydrocarbon from a subsurface reservoir, comprising the steps of: a) identifying a target reservoir, the target reservoir bearing hydrocarbons; b) locating a trigger reservoir proximate the target reservoir, the trigger reservoir being hydraulically isolated from the target reservoir; c) producing a fluid from the trigger reservoir, thereby creating an extension zone in the target reservoir, wherein a portion of the target reservoir having the extension zone is subjected to an action selected from the group consisting of zonal dilation, zonal extension, extensional mechanical fracturing, opening of natural fractures, pore volume expansion, microfracturing of mineral grains and grain cements, and combinations thereof; d) ceasing production of the fluid from the trigger reservoir; and e) producing a hydrocarbon selected from oil, gas and combinations thereof from the target reservoir.
 2. The method of claim 1, wherein step (c) comprises creating at least one of a compression zone and a compaction zone in the trigger reservoir.
 3. The method of claim 1, wherein the trigger reservoir is hydraulically isolated from the primary reservoir with a layer of impervious rock.
 4. The method of claim 1, wherein the trigger reservoir is comprised of a brine-saturated rock and the fluid is brine.
 5. The method of claim 1, wherein the fluid in the trigger reservoir is comprised of brine, water, and/or hydrocarbons.
 6. The method of claim 1, wherein step (c) comprises a hard drawdown in the trigger reservoir.
 7. The method of claim 1, further comprising the step of hydraulically stimulating the target reservoir after step (d) and/or step (e).
 8. The method of claim 1, further comprising the step of hydraulically fracturing the target reservoir before step (a) and/or step (c).
 9. The method of claim 1, wherein a well used for producing fluids from the trigger reservoir is vertically disposed.
 10. The method of claim 1, wherein a well used for producing hydrocarbons from the target reservoir is vertically disposed.
 11. The method of claim 1, wherein a well used for producing fluids from the trigger reservoir is horizontally disposed.
 12. The method of claim 1, wherein a well used for producing hydrocarbons from the target reservoir is horizontally disposed.
 13. The method of claim 1, wherein the trigger reservoir is located below the target reservoir.
 14. The method of claim 1, wherein the trigger reservoir is located above the target reservoir.
 15. The method of claim 1, wherein steps (c) are repeated.
 16. The method of claim 1, wherein the target reservoir has a relatively low permeability, relatively immobile hydrocarbons, and combinations thereof. 